The present invention relates to methods of stimulating a subterranean formation. More particularly, the present invention relates to methods of fracturing subterranean formations using a fracturing fluid comprising a self-degrading cement composition.
Hydraulic fracturing techniques commonly are used to stimulate subterranean formations to enhance the production of hydrocarbons therefrom. Conventional hydraulic fracturing operations commonly involve flowing a fracturing fluid down a well bore and into a hydrocarbon-bearing formation at a pressure sufficient to create or enhance at least one fracture therein.
Conventional fracturing fluids may comprise, inter alia, viscosifying or gelling agents to increase their viscosity, and often may include proppant particulate materials that may be deposited in the fractures. Once deposited in the resultant fractures, conventional proppant particulate materials are intended to prevent the fractures from closing so as to enhance the flow of hydrocarbons to the well bore, and thereafter to the surface. Commonly-used proppant particulate materials include, inter alia, sand, walnut shells, glass beads, metal pellets, ceramic beads, and the like.
When the fracturing fluid comprising proppant particulate materials has been placed in the formation, the proppant particulate materials undesirably may settle within the fracturing fluid to some degree before the fracture closes. This may cause the proppant pack to form at an interval different than the desired interval. Further, the viscosifying or gelling agents used in conventional fracturing fluids may form residues within the proppant pack and in the areas of the formation adjacent the fracture, which undesirably may reduce well productivity.
The success of a fracturing operation may depend, at least in part, upon fracture porosity and conductivity once the fracturing operation is stopped and production is begun. Traditional fracturing operations place a large volume of proppant particulates into a fracture and the porosity of the resultant packed propped fracture is then related to the interconnected interstitial spaces between the abutting proppant particulates. Thus, the resultant fracture porosity from a traditional fracturing operation may be closely related to the strength of the placed proppant particulates (if the placed particulates crush then the pieces of broken proppant may plug the interstitial spaces) and the size and shape of the placed particulate (larger, more spherical proppant particulates generally yield increased interstitial spaces between the particulates).
One attempt to address problems that may be inherent in tight proppant particulate packs involves placing a much-reduced volume of proppant particulates in a fracture to create what is referred to herein as a partial monolayer or “high-porosity” fracture. In such operations the proppant particulates within the fracture may be widely spaced, but still may be sufficient to desirably hold open the fracture and allow for production. Such operations may allow for increased fracture conductivity due, at least in part, to the fact the produced fluids may flow around widely spaced proppant particulates rather than merely flow through the relatively small interstitial spaces in a packed proppant bed.
Successful placement of a partial monolayer of proppant particulates presents unique challenges in the relative densities of the particulates versus the carrier fluid. Furthermore, placing a proppant particulate that tends to crush or embed under pressure may allow portions of the fracture to pinch or close once the fracturing pressure is released.
Conventional attempts to address the problems described above have involved, inter alia, the use of cement compositions as proppant materials. The cement compositions that have been used in such fashion commonly have comprised particulate carbonate salts. Such salts were intended to have dissolved out of the cement composition, theoretically enhancing the permeability of the resultant set cement sheath to a degree that may facilitate greater flow of formation fluids (e.g., hydrocarbons) to the well bore. Carbonate salts, however, generally require treatment with an acid before they may dissolve out of the cement composition. Treating the cement compositions that comprise carbonate salts with an acid, after the cement compositions have been placed within the subterranean formation, has been problematic, because such acids may tend to find the path of least resistance within the cement composition, which may result in uneven contact between the acid and the cement composition, thereby causing uneven removal of carbonate salt particulates therefrom. Thus, conventional operations that have employed proppant materials comprising cement compositions generally have not enhanced the permeability of the formation to the extent desired.